Oilfield wellbores are drilled by rotating a drill bit conveyed into the wellbore by a drill string. The drill string includes a drill pipe (tubing) that has at its bottom end a drilling assembly (also referred to as the “bottomhole assembly” or “BHA”) that carries the drill bit for drilling the wellbore. A suitable drilling fluid (commonly referred to as the “mud”) is supplied or pumped under pressure from a source at the surface down the tubing. The drilling fluid may drive a motor and then exit at the bottom of the drill bit. The drilling fluid returns uphole via the annulus between the drill string and the wellbore inside and carries with it pieces of formation (commonly referred to as the “cuttings”) cut or produced by the drill bit in drilling the wellbore.
During drilling, the equivalent circulating density (“ECD”) of the fluid in the wellbore plays a role in effective and safe hole formation. ECD refers to the condition that exists when the drilling mud circulates in the well. The friction pressure caused by the fluid circulating through the open hole and the casing(s) on its way back to the surface, causes an increase in the pressure profile along the fluid flow path that is different from the pressure profile when the well is in a static condition (i.e., not circulating). In addition to the increase in pressure while circulating, there is an additional increase in pressure while drilling due to the introduction of drill solids into the fluid. In one undesirable case, the negative effect of the increase in pressure along the annulus of the well can result in fracturing the formation. In another undesirable case, drilling into an over-pressured formation can cause flow of formation fluid or gas into the wellbore creating a kick.
The present disclosure addresses the need to control ECD as well as other needs of the prior art.